Method and system for identifying a self-sustained influx of formation fluids into a wellbore

ABSTRACT

A method of identifying a self-sustained influx of formation fluids into a wellbore includes the steps of closing an annular shut-off device and diverting an annular return flow from the wellbore through a first flow rate measurement device, measuring a flow rate of said annular return flow, measuring an inlet flow rate of fluids entering the well through a second flow rate measurement device in a fluid injection line, and identifying a self-sustained influx of formation fluids if a non-decreasing measured annular return flow rate is greater than said measured inlet flow rate.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit under 35 U.S.C. §120 to U.S. patentapplication Ser. No. 14/060,541, allowed on Aug. 18, 2015, which claimspriority under 35 U.S.C. §119(e) to U.S. Provisional Application Ser.No. 61/716,961 filed Oct. 22, 2012, incorporated herein by reference inits entirety.

BACKGROUND

1. Field

Embodiments disclosed herein relate to a method and system forperforming a flow check with a closed-to-atmosphere drilling system,resulting in improved accuracy compared to current open-to-atmospheremethods. Using methods disclosed herein, the presence of aself-sustained influx of formation fluids into a wellbore may be quicklyand safely confirmed or ruled out.

2. Background

Well control techniques are used in oil and gas operations such asdrilling, well workovers, and well completions to maintain fluidpressure at certain points in a wellbore above a formation pressure andprevent influx of formation fluids into the wellbore—known as“overbalanced” differential pressure. With the pumps on and fluidcirculating, a combination of hydrostatic pressure, friction pressureand surface pressure may combine to maintain an overbalanceddifferential pressure in a wellbore. In the event that an“underbalanced” differential pressure comes to exist in thewellbore—where fluid pressure at certain points in the wellbore is lessthan the formation pressure—formation fluids may flow into the wellbore.The fluid influx will continue until either the fluid pressure in thewellbore is increased, or the formation pressure decreases. This type offluid influx may be referred to as a “self-sustained” influx. Theself-sustained influx should be stopped and the unwanted fluid safelyremoved from the wellbore before continuing with oil and gas operations.Notably, a self-sustained influx is often generally characterized in theindustry as a “kick” along with other non-self-sustained influxesrequiring different or no remedial action. As explained below, thisexacerbates problems with accurately identifying a self-sustained influxwith current open-to-atmosphere annulus fluid systems.

A flow check procedure is a method by which a driller may, uponsuspicion or sign of a self-sustained influx, attempt to confirm whethersuch an event is indeed occurring before initiating well controltechniques. A typical flow check procedure involves positioning thedrill bit at a suitable position above the bottom of thewellbore/borehole, stopping rotation of the drillstring, and thenstopping the mud pumps. The driller then checks to see if there is anyflow returning from the well annulus (i.e., whether the well is“flowing”) with the pumps off. If the well is flowing with the pumpsoff, the driller may conclude that some type of influx is entering thewellbore.

Conventional flow check procedures today are performed entirely with theBOP open, i.e., with an open-to-atmosphere annulus fluid system. Veryoften, using an open-to-atmosphere system is inadequate for the rig crewto accurately and quickly come to a conclusion as to whether aself-sustained influx is indeed happening or not due to a variety ofother benign causes for such a perceived influx. For example, onfloating rigs, relatively small yet significant self-sustained influxesmay be difficult to observe because the conventional flow checkprocedure may be affected by rig motion and heave effects. Additionally,in some situations there may be outflow from the well that continuesafter the mud pumps are turned off due to thermal effects, welldecompression, or flow back from fractures filled previously in (i.e.,generally known as “ballooning”). Even though these conditions may causeoutflow from the well, in such cases the flow is generally not due to aself-sustained influx of formation fluids into the wellbore. Therefore,they do not constitute kicks that might otherwise require precisecontrol or response using well control procedures.

Moreover, flow check procedures take time that is often prescribed byprocedure (e.g., requiring a minimum of 10, 15, or 30 minutes). Drillersmay hesitate to risk stopping drilling operations for such periodsuntil/unless clear justification exists. And worse yet, a driller whohas had the experience of stopping to perform a flow check procedureonly to find no self-sustained influx existed may be less likely toquickly do so again—even if new circumstances justify it—if the earlierflow check resulted in delay, costs or operational problems that couldotherwise have been avoided by not performing the flow check.

Currently, the industry is ill-informed, prior to shutting in a well, toproperly and accurately detect and distinguish between self-sustainedinfluxes requiring well control techniques and temporary influxes thatdo not. Instead, the industry prefers to deal with all potentialinfluxes in a “one size fits all” manner. This leads to a multitude ofcostly and inefficient false alarms and misleading information.

3. Identification of the Objects of the Invention

A primary object of the invention is to provide a method of quickly andaccurately identifying a self-sustained influx of fluids into awellbore, such as prior to initiating well control techniques.

It is another object of the invention to provide a method of accuratelyruling out the presence of a self-sustained influx of fluids into saidwellbore.

Another object of the invention is to provide a system for identifying aself-sustained influx of fluids into a wellbore.

SUMMARY

Methods and a system for identifying, confirming or ruling out theexistence of a self-sustained fluid influx from a formation into awellbore are disclosed. One or more embodiments disclose a systemincluding a flow rate measurement device disposed in an annular returnline of a wellbore for measuring an annular return flow rate. In otherembodiments, the system may include a flow control device disposedeither upstream or downstream from the flow rate measurement device inthe annular return line. For example, the flow control device may be anautomatic flow control device controlled by sensors and software. Theflow rate measurement device may be located on the annular return linefrom a drilling rig's existing flow control device manifold while thesensors measure drilling parameters elsewhere in the system. Thesoftware in a computer acquires drilling parameters, ideally surface anddownhole variables when available from system sensors, and performscalculations based on received sensor inputs to detect a possibilitythat a self-sustained influx is happening or might happen soon. When thesituation reaches a stage that a procedure to confirm or rule out thepresence of such an influx would be recommended, a computer may displaya message indicating that such procedure should be initiated. Thecomputer provides messages to a driller's console prompting a driller tofollow the instructions based on the operation being conducted.

One such message may be to stop the drillstring rotation and to lift thedrillstring off the bottom of the wellbore. In certain embodiments, thedrillstring may continue rotating at the bottom of the wellbore. Whenthose actions are completed by the driller, the software acts to closean annular shut-off device. Closure of the annular shut-off device maybe done automatically or manually. After the annular shut-off device hasbeen closed, annular flow return is directed through the flow controldevice, if present, and the flow rate measurement device. The mud pumpsmay continue running at a normal rate, followed by incremental reductionin pump speed, if needed, during various phases of the procedure.Ultimately, mud pumps may be stopped. Annular flow return rate ismonitored and measured to confirm whether or not a self-sustained influxis occurring. If the presence of a self-sustained influx is confirmed,the software may partially close the flow control device until flow outequals flow in, in case the mud pumps are on, or completely close theflow control device if the pumps are off. If a flow control device isnot present, the software may send a message to the driller alerting ofthe presence of a self-sustained influx. If the presence of aself-sustained influx is not confirmed with the pumps on, the system mayinstruct the driller to reduce the speed of the pumps, or completelyshut the pumps off If annular return flow rate reaches zero with thepumps off, the presence of a self-sustained influx is then ruled out,and the system instructs the driller to open the annular shut-off deviceand resume normal drilling activity.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is illustrated in the accompanying drawings wherein,

FIG. 1 illustrates a schematic view of an implementation of the systemincluding a flow rate measurement device and flow control device foridentifying a self-sustained influx.

FIG. 2A illustrates a schematic view of an implementation of the systemincluding a flow rate measurement device and flow control device foridentifying a self-sustained influx.

FIG. 2B illustrates a schematic view of an implementation of the systemincluding a flow measurement device for identifying a self-sustainedinflux.

FIGS. 3A-3C illustrate a method of identifying a self-sustained influxusing the systems shown in FIGS. 1, 2A and 2B.

FIGS. 4A and 4B illustrate displays of measured flow in and flow out ofa wellbore generated using methods of FIGS. 3A-3C.

FIGS. 5A and 5B illustrate displays of measured flow in and flow out ofa wellbore generated using methods of FIGS. 3A-3C.

FIGS. 6A and 6B illustrate displays of measured flow in and flow out ofa wellbore generated using methods of FIGS. 3A-3C.

DETAILED DESCRIPTION

FIG. 1 illustrates a system 10 that includes a tubular drillstring 20suspended from a drilling rig 90. The drillstring 20 has a lower end 22which extends downwardly through a BOP stack 30 and into borehole/wellbore 12 in a formation 14. A drill bit 26 is attached to the lower end22 of drillstring 20. A drillstring driver or turning device 38,comprising either a rotary drive system (not shown) or a top drivesystem 38, is operatively coupled to an upper end 24 of the drillstring20 for turning or rotating the drillstring 20 along with drill bit 26 inthe borehole 12. A conventional surface fluid/mud pump 40 pumps fluidfrom a surface fluid reservoir 42 through a fluid injection line 48,through the upper end 24 of drillstring 20, down the interior ofdrillstring 20, through drill bit 26 and into a borehole annulus 18. Theborehole annulus 18 is created through the action of turning drillstring20 and attached drill bit 26 in borehole 12 and is defined as theannular space between the interior/inner wall or diameter of theborehole 12 and the exterior/outer surface or diameter of thedrillstring 20.

A conventional BOP stack 30 is coupled to well casing 16 via a wellheadconnecter 28. Typically, the BOP stack 30 includes one or more piperams, one or more shear rams, and one or more annular BOPs 32. The BOPstack 30 may further include one or more additional annular shut-offdevices 31 for use with flow check procedures and the system describedherein. Alternatively, the one or more additional annular shut-offdevices 31 may be separate from the BOP stack 30. When drilling isstopped (i.e., the drillstring driver 38 is no longer turning thedrillstring 20 and drill bit 26), the one or more conventional annularBOPs 32 may be closed to effectively close the borehole annulus 18/wellbore 12 from the atmosphere.

Referring still to FIG. 1, a flow control device line 56 is coupledbetween the conventional BOP stack 30 via flow control device line valve36 and the surface fluid reservoir 42 via rig well control flow controldevice manifold 86. The rig well control flow control device manifold 86includes a flow control device 70, such as a choke, disposed in the flowcontrol device line 56. The flow control device 70 controls flow ratethrough the flow control device line 56 thereby controlling pressureupstream of the flow control device 70 and thus, backpressure to thewell bore annulus 18 while the BOP 32 is closed. A mud-gas separator 46and a shale shaker 44 are also preferably fluidly coupled to the flowcontrol device line 56 and are positioned between the flow controldevice 70 and surface fluid reservoir 42. Thus, when flow control deviceline valve 36 and flow control device 70 are opened after the BOP 32 isclosed, fluid from the borehole annulus 18 is permitted to flow upthrough BOP stack 30, through flow control device line valve 36, throughflow control device line 56, through rig well control flow controldevice manifold 86, through mud-gas separator 46, through shale shaker44 and into surface fluid reservoir 42.

As shown in FIG. 1, an outlet fluid flow rate measurement device 50,such as a volume or mass flow rate meter, is preferably used to measurethe fluid flow rate out of the well bore 12 while the conventionalblow-out preventer 32 is closed. Such fluid flow rate measurement device50 is preferably a Coriolis flow rate meter, an ultrasonic flow ratemeter, a magnetic flow rate meter or a laser-based optical flow ratemeter, but may be any suitable type known to those skilled in the art.The outlet fluid flow rate measurement device 50 is arranged anddesigned to generate a signal F_(out)(t), which is representative ofactual annular return flow rate out of the well bore 12 through the flowcontrol device line 56 as a function of time (t). The outlet fluid flowrate measurement device 50 transmits the signal F_(out)(t), preferablyin real time, to the central control unit 80, which receives andprocesses the signal. The outlet fluid flow rate measurement device 50is preferably disposed in the flow control device line 56 between theflow control device 70 and the rig mud gas separator 46. However, theoutlet fluid flow rate measurement device 50 may alternatively bedisposed in the flow control device line 56 upstream of the flow controldevice 70 (i.e., between the well bore annulus 18 and the flow controldevice 70).

As shown in FIG. 1, an inlet pressure measurement device 76, such as apressure sensor, is disposed in the fluid injection line 48. However,the inlet pressure sensor 76 could alternatively be disposed elsewherein the fluid injection line 48, but preferably in close proximity to theinlet flow rate measurement device 52. The inlet pressure measurementdevice 76 is arranged and designed to generate signal P_(in)(t), whichis representative of the pressure in the fluid injection line 48 (i.e.,the standpipe pressure) as a function of time (t). The inlet pressuremeasurement device 76 transmits signal P,_(in)(t), preferably in realtime, to the central control unit 80, which receives and processes thesignal.

An outlet pressure measurement device 64, such as a pressure sensor, isdisposed in the choke line 56 preferably in proximity to the rig wellcontrol choke manifold 86 and upstream of the flow control device 70.The outlet pressure measurement device 64 is arranged and designed togenerate a signal P_(out)(t), which is representative of the pressure inthe choke line 56 as a function of time (t). When the outlet pressuresensor 64 is disposed upstream of the flow control device 70, thepressure sensor measures pressure representative of the casing pressure(or the choke manifold pressure on floating rigs). The outlet pressuremeasurement device 64 transmits the signal P_(out)(t) in real time tothe central control unit 80, which receives and processes the signal.

In certain embodiments, referring to FIG. 2A, a flow check line 57 maybe coupled between the annular BOP 32 or annular shut-off device 31 andsurface fluid reservoir 42. Those skilled in the art will understandthat although shown in separate Figures, flow check line 57 and flowcontrol device line 56 (FIG. 1) may be incorporated into the samesystem, and often are. The flow check line 57 may include a flow controldevice 59, such as a choke, and a flow rate measurement device 58.Alternatively, the flow check line 57 may include only a flow ratemeasurement device 58 without including a flow control device, as shownin FIG. 2B. Such fluid flow rate measurement device 58 is preferably aCoriolis flow rate meter, an ultrasonic flow rate meter, a magnetic flowrate meter or a laser-based optical flow rate meter, but may be anysuitable type known to those skilled in the art. The flow ratemeasurement device 58 is arranged and designed to generate a signalF_(out)(t), which is representative of actual annular return flow rateout of the well bore 12 through the flow check line 57 as a function oftime (t). The flow rate measurement device 58 transmits the signalF_(out)(t), preferably in real time, to the central control unit 80,which receives and processes the signal.

The flow check line 57 may be coupled with the well casing 16 below theannular shut-off device 31, and thereby be in fluid communication withannular return flow in the borehole annulus 18. Annular shut-off device31 may be a BOP or also what is called an annular BOP, and may belocated anywhere along a length of the well casing 16. The main purposeof the annular shut-off device 31 is to close the borehole annulus 18,thereby converting the open-to-atmosphere system to aclosed-to-atmosphere system, and forcing the return fluid from theborehole annulus 18 through a flow control device 59 and a flow ratemeasurement device 58. Thus, when flow check line 57 is opened by thetime the annular shut-off device 31 is closed, fluid from the boreholeannulus 18 is permitted to flow up through BOP stack 30, through openedoutlet valve 61, through flow check line 57, through flow control device59 and flow measurement device 58, through mud-gas separator 46, throughshale shaker 44, and into surface fluid reservoir 42. Alternatively, onrigs using an annular blowout preventer 32 above the BOP stack 30 forthis purpose, existing flow paths may be used (e.g., through the flowcontrol device line 56 and flow control device 70 and flow measurementdevice 50).

Other configurations may use, for example, an annular preventer,diverter element located at the rig floor, or alternative annular shutoff device located above the rig BOP to divert annular return flow to aseparate manifold containing the flow control device and flow ratemeasurement device. In a preferred configuration, for rigs using subseaBOP's, a dedicated annular shut-off device located near the top of themarine riser, but below the rig's telescopic riser slip joint, may beused to divert return flow from a flow outlet below the annular to adedicated manifold containing the flow control device and flow ratemeasurement device, with returns subsequently directed to mud/gasseparation equipment, overboard lines, or back to the mud system (e.g.,via a trip tank or similar).

Flow control device 59 may control flow rate through the flow check line57, and thus, apply back pressure on the wellbore annulus 18 whileannular shut-off device 31 is closed. An outlet pressure measurementdevice 64, such as a pressure sensor, may be disposed in the flow checkline 57 preferably upstream of the flow control device 59. The flowcontrol device 59 may be controlled by software with input from flowrate measurement device 58 downstream of the flow control device 59.

Referring still to FIGS. 1, 2A and 2B, an inlet fluid flow ratemeasurement device 52, such as a volume or mass flow rate meter ispreferably used to measure the fluid flow rate into the well bore 12while the conventional blow-out preventer 32 or annular shut-off device31 is closed. The inlet fluid flow rate measurement device 52 ispreferably a coriolis flow rate meter, an ultrasonic flow rate meter, amagnetic flow rate meter or a laser-based optical flow rate meter, butmay be any suitable type known to those skilled in the art.Alternatively, even a simple device to measure the strokes of theconventional surface fluid/mud pump 40 as a function of time can serveas an inlet fluid flow rate measurement device. The inlet fluid flowrate measurement device 52 is arranged and designed to generate a signalF_(in)(t), which is representative of actual fluid flow rate through thefluid injection line 48 (i.e., an inlet line coupled between pump 40 anddrill string 20) as a function of time (t). The inlet fluid flow ratemeasurement device 52 transmits the signal F_(in)(t) in real time to thecentral control unit 80, which receives and processes the signal. Theinlet fluid flow rate measurement device 52 is preferably disposed inthe fluid injection line 48 between the conventional surface fluid/mudpump 40 and the standpipe manifold (not shown) such that the inlet fluidflow rate measurement device 52 measures fluid flow rate into theborehole 12.

A central control unit 80 is preferably arranged and designed to receivemeasurement signals from a number of the previously described flow ratemeasurement devices. The central control unit 80 may use the receivedsignals to generate control signals to control either flow controldevice 70 or 59 and flow therethrough. The central control unit 80 maythen transmit these control signals to the flow control devices 70 or59, thereby controlling the flow through either flow control device line56 or flow check line 57. Central control unit 80 may be any type ofcomputing device preferably having a user interface and software 81installed therein, such as a computer, that is capable of, but notlimited to, performing one or more of the following tasks: receivingsignals from a variety of measurement devices, converting the receivedsignals to a form exploitable for computing and/or monitoring, using theconverted signals for computing and/or monitoring desired parameters,generating signals representative of computed parameters, andtransmitting generated signals. With respect to the flow control devices70 and 59, the central control unit 80 is preferably arranged anddesigned to transmit generated control signals wirelessly or via a wiredlink (shown by the dotted lines) to the flow control devices 70 and 59.The control signals received by the flow control devices 70 or 59 fromthe central control unit 80 cause the orifices of the flow controldevices 70 and 59 to either fully open, fully close, or to open or closeto some position therein between. While the flow control devices 70 and59 may be controlled automatically by the central control unit 80 asdescribed above, the flow control devices 70 and 59 may also be manuallycontrolled by an operator to adjust the fluid flow rate or pressurethrough the flow control devices 70 and 59 at the discretion of theoperator.

In certain embodiments, the system may be used in conjunction withadvanced well monitoring and/or kick detection software. Such softwaremay utilize actual or calculated downhole drilling parameters receivedat the central control unit 80 to detect onset of a possibleself-sustained influx situation. Whether triggered by influx detectionsoftware, conventional instrumentation, routine policy, or a driller'sdesire to understand suspicious downhole conditions, the driller mayperform a flow check procedure to help identify, or rule out,self-sustained influx from a formation. Once the procedure is started,the system may perform a series of programmed steps intended to identifyany self-sustained influx, whether or not any other false influxindications exist, as these may be due to other, relatively benigncauses (e.g., continued pumping using rig, booster or auxiliary pumps,drillpipe u-tubing, formation ballooning-related flowback, nuisance zonedepletion, mud system drain-back, etc.).

Methods 300 related to using any of the systems 10 shown in FIGS. 1, 2Aand 2B are now described by reference to FIGS. 3A-3C in accordance withone or more embodiments. Reference numerals that reference the system 10shown in FIGS. 1, 2A and 2B are indicated in parentheses. Initiating themethod may be automatic or not (see process start 301 in FIG. 3A). Forexample, the method may be automatically initiated without requiringauthorization from a driller or operator, such as upon receivingindications of conventional known causes for performing a check forconfirming or ruling out the presence of a self-sustained influx. Themethod may also be manually initiated by an operator, or remotelyinitiated via computer networks. Initially, the drillstring (20) may bestopped from rotating (see process step 302), and the wellbore annulusis closed using an annular shut-off device (31, 32) (see process step304). Alternatively, the drillstring may continue rotating even afterthe wellbore annulus is closed using an annular shut-off device adaptedto close around a rotating drillstring. Annular return flow from thewellbore annulus is diverted through a flow rate measurement device (50,58) in an annular return line (56, 57) (see process step 306).

The inlet flow rate of drilling fluids into the well is measured by aflow rate measurement device (52) (see process step 308), whichgenerates a corresponding signal F_(in)(t) (see data output 310).Likewise, annular return flow rate of fluids returning from well annulusis measured by a flow rate measurement device (50, 58) (see process step312), which generates a corresponding signal F_(out)(t) (see data output314). Signals F_(in)(t) and F_(out)(t) may be transmitted to a centralcontrol unit (80), where software (81) installed on the central controlunit processes the signals (see process step 316). Signals F_(in)(t) andF_(out)(t) may be displayed to a user on a monitor or other display (seedata output 318), where the signals may be monitored (see process step320). The signals are monitored to identify the presence of aself-sustained influx of formation fluids into the wellbore (see logicbox 322).

FIGS. 4A and 4B illustrate an example display of signals F_(in)(t) andF_(out)(t) generated (see data output 318 in FIG. 3A). FIG. 4Aillustrates a scenario in which a self-sustained influx is identified—anon-decreasing measured annular return flow rate, indicated by signalF_(out)(t), is greater than said measured inlet flow rate indicated bysignal F_(in)(t). Upon identifying a self-sustained influx in thewellbore, well control procedures may be commenced (see process step 324in FIG. 3A). Or, in embodiments including a flow control device (70, 59)in the annular return line, the flow control device may be closedautomatically or manually to equalize flow rates of the annular returnand inlet flow. FIG. 4B illustrates a scenario in which a self-sustainedinflux is not immediately confirmed. Here, the annular return flow rateremains substantially the same as the constant inlet flow rate. However,FIG. 4B cannot affirmatively rule out the possibility of aself-sustained influx at a further reduced inlet flow rate or staticconditions.

Returning to FIG. 3A, per company policies and procedures, and to moreaccurately confirm or rule out the presence of a self-sustained influxinto the wellbore, the operator may reduce the inlet flow rate of fluidsinto the wellbore by a certain amount (see process step 326 in FIG. 3A).It will be understood by those skilled in the art that an operator maybegin the flow check procedure by immediately reducing the inlet flowrate. To do so, the operator may reduce pump (40) speed. For example,the operator may reduce inlet flow rate by at least 10 gallons perminute (“gpm”), or at least 50 gpm, or at least 100 gpm, and up to 200gpm, or up to 400 gpm, or up to 600 gpm, or greater. The inlet flow rateof drilling fluids into the well is measured by the flow ratemeasurement device (52) (see process step 328), which generates acorresponding signal F_(in)(t) (see data output 330). Likewise, annularreturn flow rate of fluids returning from the well annulus is measuredby the flow rate measurement device (50, 58) (see process step 332),which generates a corresponding signal F_(out)(t) (see data output 334).Signals F_(in)(t) and F_(out)(t) may be transmitted to a central controlunit (80), where software (81) installed on the central control unitprocesses the signals (see process step 336). Signals F_(in)(t) andF_(out)(t) may be displayed to a user on a monitor or other display (seedata output 338), wherein the signals are monitored (see process step340). The signals are monitored to identify the presence of aself-sustained influx of formation fluids into the wellbore (see logicbox 342).

FIGS. 5A and 5B illustrate an example display of signals F_(in)(t) andF_(out)(t) generated (see data output 338 in FIG. 3B). FIG. 5Aillustrates a scenario in which a self-sustained influx is identified—anon-decreasing measured annular return flow rate, indicated by signalF_(out)(t), remains greater than said reduced inlet flow rate indicatedby signal F_(in)(t). Upon identifying a self-sustained influx in thewellbore, well control procedures may be commenced (see process step 344in FIG. 3B). Or, in embodiments including a flow control device (70, 59)in the annular return line, the flow control device may closedautomatically or manually to equalize flow rates of the annular returnand inlet flow. FIG. 5B illustrates a scenario in which a self-sustainedinflux is not immediately confirmed—after reducing the inlet flow rate,the annular return flow rate decreases to an amount equal to or lessthan the constant inlet flow rate. However, FIG. 5B cannot affirmativelyrule out the possibility of a self-sustained influx at a further reducedinlet flow rate or static conditions.

Returning again to FIG. 3B, per company policies and procedures, and toidentify or rule out the presence of a self-sustained influx into thewellbore at further reduced inlet flow rate or static conditions, theoperator may reduce the inlet flow rate to substantially zero (seeprocess step 346). It will be understood by those skilled in the artthat an operator may begin the flow check procedure by immediatelyreducing the inlet flow rate to substantially zero. Inlet flow rate isstill measured by flow rate measurement device (52) (see process step328) and annular return flow rate measured by flow rate measurementdevice (50, 58) (see process step 348). Representative signals F_(in)(t)and F_(out)(t) are generated to indicate inlet flow rate and annularreturn flow rate, respectively (see data outputs 330 and 350). Thesignals are transmitted to central control unit (80), where software(81) installed on the central control unit processes the signals (seeprocess step 352). Signals F,_(in)(t) and F_(out)(t) may be displayed toa user on a monitor or other display (see data output 354), where thesignals may be monitored (see process steps 356). The signals aremonitored to either identify or rule out the presence of aself-sustained influx of formation fluids into the wellbore (see logicbox 358).

FIGS. 6A and 6B illustrate an example display of signals F_(in)(t) andF_(out)(t) generated (see data output 354). FIG. 6A illustrates ascenario in which a self-sustained influx is identified—a non-decreasingmeasured annular return flow rate, indicated by signal F_(out)(t),remains greater than said fully reduced inlet flow rate indicated bysignal F_(in)(t), which has been reduced to zero. Upon identifying aself-sustained influx, well control procedures may be commenced (seeprocess step 360 in FIG. 3C). Or, in embodiments including a flowcontrol device (70, 59) in the annular return line, the flow controldevice may be closed automatically or manually to equalize flow rates ofthe annular return and inlet flow. FIG. 6B illustrates a scenario inwhich the presence of a self-sustained influx is affirmatively ruledout—the annular return flow rate continues to decrease to substantiallyzero after the inlet flow rate is reduced to zero. Upon ruling out thepresence of a self-sustained influx into the wellbore, prior oil and gasoperations in the well may generally be resumed (see process step 362 inFIG. 3C).

In certain embodiments, the system described herein may be activatedautomatically (if optionally set to be triggered by detection meanslinked to conventional causes for performing flow check methodsdescribed herein, such as specified rate-of-penetration (“ROP”) changes,movement of the bit to predetermined depths during trips, downhole tooloutput changes, reaching of specific sensor threshold values, etc.) withor without confirming authorization from the driller. System activationmay also be triggered, if desired, by use of remote commands viacomputer networks or triggering devices located, for example, insupervisors' offices.

When activated, the system may be configured to provide messages orinstructions to the driller, perhaps based on the specific operationbeing conducted. For example, if methods described herein while drillingare called for, the system may prompt the driller to stop rotating thedrillstring and to lift the drillstring off the bottom of the well to apre-determined position. Closure of the annular shut-off device may beprogrammed to occur automatically (one implementation when control ofthe annulus shut-off device is separate from the rig's BOP controls), ormay be accomplished by provision of instruction to the driller as towhat action to take to ensure annulus closure and/or system flow pathalignment. The system may provide pre-programmed advice to the drilleras to whether or not there is need to reduce pump speed to achieve oneof several preselected pressure control objectives prior to or duringannular shut-off, perhaps including instructions to simply stop relevantpumps.

After the annular flow has been routed through the system, signalsreceived from the flow rate measurement devices may be used to confirmwhether or not a self-sustained influx is happening. If the presence ofa self-sustained influx is confirmed (by automated flow analysis) andthe pumps remain on, the software may optionally be used toautomatically close the flow control device until flow out equals flowin (i.e., achieve a “dynamic” shut-in”). Alternatively, the system maybe set up to close the flow control device completely in case the pumpsare off or are turned off (thereby completing a conventional full shutin against the closed flow control device).

If the system is activated to perform methods described herein withpumps on and self-sustained influx of formation fluids is not confirmedby monitoring flow rates, the system may instruct the driller tosubsequently reduce the speed of the pumps, and eventually, completelystop the pumps. The software may look for confirmation of self-sustainedinflux at all times and if such an influx is confirmed at or after thepumps have stopped, the software may automatically close the flowcontrol device to stop further influx. If flow rate of the annularreturn flow continues to decrease and reaches zero after the pumps havebeen turned off, therefore confirming that there is no self-sustainedinflux, the system may advise that the well is static and the flow checkis “negative.” For example, the system may display an appropriate signalto a user on a graphical user interface (e.g., “Kick” or “No Kick”). Orfor example, the system may display a green signal after ruling out thepresence of a self-sustained influx, or display a red signal afterconfirming the presence of a self-sustained influx. Other indicators anddisplays may also be used in accordance with one or more embodiments ofthe system described herein. Drillers may be advised that there is nodownhole condition that would preclude immediate return to normaldrilling operations (e.g., reopening the annulus, realigning normalreturn flow paths and resuming the normal drilling activity).

The following related examples are intended to illustrate possible usesof the system and are provided here to clarify typical, though not all,possible usages. While drilling a 12¼″ hole at a flow rate of 800 gpmusing a rig with a surface BOP and an open-to-atmosphere circulationsystem, a driller detects a change in drilling parameters that indicatethat an influx may be occurring (e.g., a “drilling break”/ROP change, anunexpected slow rise in mud pit volumes, a change in return fluidcomposition or similar). Recognizing that a possible influx event isoccurring or may be about to occur, the driller may wish (or be requiredby policy) to perform a flow check (e.g., confirming or ruling out thepresence of a self-sustained influx of formation fluids into the well).

The driller optionally stops rotating the drillstring and lifts thedrillstring off the well bottom to a predetermined position. In certaininstances, the driller may slow an inlet flow rate of fluids through thefluid injection line (e.g., by slowing the pump rate) to a specificrate. For example, the pump rate may be calculated by the system toreduce an equivalent circulating density (“ECD”) of fluid the boreholeby a calculated amount of friction that will be added when fluid isdiverted through the flow check line. In this example, the system maycalculate that a flow rate of 475 gpm through the system would cause theECD at a bottom of the well to be the same as while circulating throughan open annulus at 800 gpm, and the driller may be advised to reducepump speed accordingly before continuing the flow check procedure.

With pump speed reduced to adjust the inlet flow rate to 475 gpm, anannular shut-off device (either a BOP or separate annular shut-offdevice) may be closed, and an outlet valve on the flow check lineleading to the flow rate measurement device may be opened, therebydiverting the 475 gpm annular return flow stream through the open flowrate measurement device and flow control device (if installed on theannular return flow line). The system compares the annular return flowrate measured by the flow rate measurement device in the flow check linewith the inlet flow rate measured by the flow rate measurement device inthe fluid injection line to confirm, or rule out, the presence of aself-sustained influx of formation fluid into the well (in accordancewith method steps described above in reference to FIGS. 3A-3C). Incertain embodiments, an annular return flow rate measured by the flowrate measurement device in the flow check line is monitored and observedfor a predefined amount of time before any conclusion is made about theabsence of a self-sustained influx. For example, the amount of time maybe at least 5 seconds, at least 30 seconds, at least 1 minute, and up toabout 5 minutes, or up to about 15 minutes, or up to about 30 minutes.Any predefined amount of time may be used. Further, a separate, butdifferent, generally short predefined amount of time (as may be neededfor data analysis) may be similarly utilized before presence of aself-sustained influx is identified.

The flow rate measurement device triggers a flow control device torespond to either relative flow rates between annular return flow andinlet flow or a non-decreasing trend of annular return flow, the systemmay advise the driller that a possible self-sustained influx event hasbeen confirmed and action to temporarily balance net flow has been taken(e.g., the system has moved to perform a “dynamic” shut in if the pumpsare on, or has moved to perform a full shut-in if the pumps are alreadyoff). The driller may then take the necessary actions to control thewell as required, following the company's policies, or known wellcontrol procedures. In order to minimize as much as possible the influxvolume into the wellbore, the driller may be advised to slowly stop thepump (allowing the system to automatically close the flow control deviceas needed to keep flow in and flow out in balance) as the initial stepof the shut-in, should a dynamic shut in condition be established. Uponruling out the presence of a self-sustained influx of fluid into thewellbore, the system may display confirmation of such to the driller,and the system may reopen the annular shut-off device and close the flowcheck line leading to the flow rate measurement and flow control devices(or advise the driller to perform these steps).

Advantageously, using the system in the manner described herein, anunscheduled flow check procedure resulting in clear, recordeddocumentation of the absence or presence of a self-sustained influx offormation fluid may be routinely completed much faster than usingconventional flow check procedures. Another advantage of the system andmethods herein described is that confirming a self-sustained influx isachieved with much more certainty than using conventionalopen-to-atmosphere methods employed today. Currently, the driller mayfinish a conventional flow check procedure and still be unable to reacha definitive conclusion as to whether a self-sustained influx is or isnot occurring. When in doubt, additional procedures are usuallyconducted to try to reach a conclusion, which requires more time spent.If a self-sustained fluid influx event is confirmed by the methods andsystem described herein, it may be controlled by the system if a flowcontrol device is implemented on an annular return line, either manuallyor automatically, permitting simple, straightforward transfer of wellcontrol responsibility to the crew using conventional rig BOP and wellcontrol equipment.

The terms and descriptions used herein are set forth by way ofillustration only and are not meant as limitations. Those skilled in theart will recognize that many variations are possible within the spiritand scope of the invention as defined in the following claims, and theirequivalents, in which all terms are to be understood in their broadestpossible sense unless otherwise indicated.

1. A method of identifying a self-sustained influx of formation fluidsinto a wellbore (12) being drilled in a formation (14), the methodcomprising the steps of: closing an annular shut-off device (31) anddiverting an annular return flow from the wellbore through a first flowrate measurement device (50, 58); measuring a flow rate of said annularreturn flow; measuring an inlet flow rate of fluids entering thewellbore through a second flow rate measurement device (52) in a fluidinjection line (48); and upon determining that the measured annularreturn flow rate is greater than the measured inlet flow rate,identifying the presence of a self-sustained influx of formation fluidsbased upon a non-decreasing measured annular return flow rate.
 2. Themethod of claim 1, further comprising reducing said inlet flow rate,and, upon determining that the measured annular return flow rate isgreater than the measured inlet flow rate, identifying the presence of aself-sustained influx of formation fluids based upon a non-decreasingmeasured annular return flow rate.
 3. The method of claim 2, furthercomprising the steps of: fully reducing said inlet flow rate tosubstantially zero, and, upon determining that the measured annularreturn flow rate is greater than the measured inlet flow rate,identifying the presence of a self-sustained influx of formation fluidsbased upon a non-decreasing measured annular return flow rate.
 4. Themethod of claim 3, further comprising the step of: ruling out thepresence of a self-sustained influx of formation fluids at existing flowrates based upon a decreasing measured annular return flow rate.
 5. Themethod of claim 1, further comprising: generating a signal F_(out)(t)representative of said annular return flow rate; generating a signalF_(in)(t) representative of said inlet flow rate; and transmitting saidsignals F_(in)(t) and F_(out)(t) to a central control unit, whichreceives said signals F_(in)(t) and F_(out)(t) and computes a deltabetween said signals F_(in)(t) and F_(out)(t).
 6. The method of claim 5,further comprising the step of increasing back pressure on said annularreturn flow using a flow control device when a self-sustained influx isidentified.
 7. The method of claim 6, further comprising the step ofincreasing back pressure on said annular return flow by an amountrequired to decrease said annular return flow indicated by signalF_(out)(t) to substantially the same as said inlet flow rate indicatedby signal F_(in)(t).
 8. The method of claim 7, further comprising thestep of automatically increasing back pressure on said annular returnflow by said central control unit.
 9. The method of claim 4, furthercomprising the step of reopening the annular shut-off device afterruling out the presence of a self-sustained influx of formation fluidsinto the wellbore.
 10. The method of claim 1, further comprising thestep of stopping rotation of a drillstring (20) or lifting saiddrillstring off a well bottom.
 11. A method of identifying or ruling outa self-sustained influx of formation fluids into a wellbore (12) beingdrilled in a formation (14), the method comprising the steps of: closingan annular shut-off device (31) and diverting an annular return flowfrom the wellbore through a first flow rate measurement device (50, 58);measuring a flow rate of said annular return flow; measuring an inletflow rate of fluids entering the wellbore through a second flow ratemeasurement device (52) in a fluid injection line (48); and upondetermining that the measured annular return flow rate is greater thanthe measured inlet flow rate, ruling out the presence of aself-sustained influx of formation fluids at existing flow rates basedupon a decreasing measured annular return flow rate.
 12. The method ofclaim 11, further comprising ruling out the presence of a self-sustainedinflux of formation fluids based upon the measured annular return flowrate decreasing to substantially zero.